1. Field of the Invention
The present invention pertains to packing which can be used in injection wellbores which facilitate the recovery of heavy oils, shale oils, tars, and in well shafts for in situ coal gasification. The packing can also be used in light oil and gas production wells. The packing is used to control the quantity of hydrocarbons in the wellbore of a producing well; to limit the backflow of hydrocarbons into and reduce space available to hydrocarbons within the wellbore of an injection well; and, to act as a heat sink in all applications, preventing damage to well components in case of a well fire or combustion in the immediate area of the well.
2. Background of the Invention
In situ combustion is a generic term used to describe burning of hydrocarbons in a subterranean formation. In situ combustion, in the form of fire flooding, is generally used in enhanced recovery of heavy oils and tar sands, and can be used in the recovery of light oils. In situ combustion can also be used for retorting oil shale.
The well packing system of the present invention, although focused on in-situ combustion for heavy oil recovery, is also applicable to tar sands, shale oil and light oil. The packing can also be used in well shafts for in-situ coal gasification processes.
The in situ combustion process for enhanced heavy oil recovery is a thermal recovery technique in which a burning fuel front is initiated in the oil-containing formation near an injection well and is used to push heated oil toward production wells. Typically, the formation in which the oil lies is preheated with steam or a type of downhole heater; then oxygen containing gas (frequently air), is injected into the formation. Ideally, ignition of the oil in the formation occurs evenly across the deposit face and as the oxygen-containing gas injection continues, the hydrocarbons around the injection well are burned at a controlled rate to ensure integrity of the injection well until the burning front is moved some distance from the well.
However, ideal operations are seldom realized. Formation heterogeneities and gas supply problems can result in temperatures in and around the injection well that are sufficiently high to adversely affect the structural integrity of the well casing and other down-hole equipment. When the oxygen containing gas is oxygen enriched air, carbon steel equipment can ignite and burn. Damage from injection well fires can cost $100,000 per well or more to repair.
FIG. 1 shows a schematic of a typical injection well 10 for in situ combustion enhanced oil recovery. Generally, all the below ground 12 tubulars such as surface casing 14 (which extends above ground), casing 16, and tubing 18, for example, are carbon steel The packer 22, used to isolate the annulus 28 from injection region 30 and from hydrocarbon-containing formation 26, is also commonly comprised of carbon steel and has elastomeric seals 20.
Techniques used to mitigate the problem of injection well fires by protecting well equipment from damage include (1) use of alloys for fabrication of the tubulars and packer;(2) "fail safe" inert gas or water dump systems, including down hole temperature measurement devices connected with the inert gas or water dump system;(3) use of down-hole temperature measurement as part of a shut off system for the oxygen-containing injection gas; and (4) combinations of these techniques.
The cost of alloys such as Incoloy 825 and Monel which are used to replace carbon steel is about 20 to 40 times the cost equivalent of the carbon steel. Even when alloy use is restricted to lower casing 24, packer 22 and other equipment below packer 22, the use of alloy material increases well costs over the range of about $10,000 to $50,000 per well. In addition, the use of alloys does not prevent overheating of the packer 22 in the event of a well fire, and such heating can cause a change in the properties of the elastomeric seal 20, and loss of the seal between the annulus 28 and injection region 30 of the well.
Water is often used in the annulus 28 region to keep packer 22 cool and to act as a quench if the well becomes hot enough to affect elastomer seals 20. However, even a "fail safe" dump system may not provide sufficient protection for tubulars down hole of packer 22. In addition, "fail safe" systems which use water or inert gas (such as nitrogen) for quenching are not always reliable. The down hole temperature sensing devices used to initiate the "fail safe" systems are unreliable for long term use due to the environment in which they are placed. In addition, the response of the dump system may be too slow to prevent damage to the equipment.
The risk of high down-hole temperatures is increased in oxygen-enriched air or oxygen fire floods because of the increase in combustion rate with increased oxygen content. At oxygen concentrations greater than about 40%, sufficient energy can be released to ignite and burn carbon steel tubulars.
As the combustion zone in an in-situ combustion process nears the production wells, the oil is heated to its autoignition temperature. When the oxygen containing gas enters the production well through the formation, spontaneous combustion occurs and extremely high temperature levels result. Down hole thermocouples can be used to sense the approach of the combustion front in time to permit use of a water dump system. However, such systems are expensive, may fail to adequately respond, and traditionally have not been used. Thus, the production well is at risk in a manner similar to the injection well.
The following art is related to the technology discussed above:
Allen, T. O. and Roberts, A. P., "Production Operations", Second Edition, Oil and Gas Consultants International, Inc., Tulsa, Okla., (1982), Volume 2, pp. 35-31 discusses the problem of sand control within production oil wells and describes many of the common designs of oil well packing currently used to hold formation sand in place, preventing the influx of sand into the well without excessive reduction in well productivity. The design includes methods of sizing the packing relative to sand size, describes the kinds of materials commonly used, and discloses methods for placing packing inside the well.
G. Pusch, "Testing Oil Recovery Methods. In Situ Combustion with Oxygen Combined with Water Injection (ISCOWI)--A New Tertiary Oil Recovery Method", Eidoel Kohle, Erdgas, Petrochem Vol. 30, No.1, pp 13-25 (1977) describes the use of filling materials in reservoirs down-hole of the packer. Mr. Pusch states that he believes it is a basic precondition of the use of oxygen enriched air injection that free hollow spaces in the well, at least in the reservoir range below the packer, be filled with sand or gravel or porous cement, wherein sufficient permeability of the packing is maintained.
U.S. Pat. No. 4,583,594 to Kojicic, dated April 22, 1986 and Titled: Double Walled Screen-Filter with Perforated Joints, describes a pair of spaced concentric screens connected with perforated joints closing the lower end of the filtering space. The annular space is filled with a filtering materials pack comprising gravel or synthetic balls. An upper joint acts as a cover cap of the annular filtering space to seal the filtering materials pack.
U.S. Pat. No. 4,042,026 to Pusch et al., dated Aug. 16, 1977, and Titled: Method for Initiating an In-Situ Recovery Process by the Introduction of Oxygen, describes a method for initiating an in situ recovery process or for restarting the operation in a subterranean formation by the introduction of oxygen into the formation. The cavities of the reservoir region within the injection bore hole (in which contact between oxygen and combustible materials is possible) are filled with porous filling material, such as sand, grit packing or Raschig rings.
U.S. Pat. No. 3,010,516 to Schleicher, dated Nov. 28, 1961, and Titled: Burner and Process for In Situ Combustion, discloses a porous refractory burner used to combust injected gas mixtures within the pores of the burner.
U.S. Pat. No. 2,777,679 to Ljungstrom, dated Jan. 15, 1957, and Titled: Recovering Sub-Surface Bituminous Deposits by Creating a Frozen Barrier and Heating In Situ, describes the use of granular material such as sand in the annular region above the well packer.
U.S. Pat. No. 2,119,563 to Wells, dated June 7, 1938, and Titled: Method of and Means for Following Oil Wells, discloses means for maintaining oil flow while filtering petroleum through the use of packing having a specific gravity at least twice the specific gravity of the petroleum bearing stratum. Iron balls are identified as a preferred packing material.
Several of the references above disclose the use of well packings for the purpose of filtering out sand or other well debris flowing into producing wells. Other references discuss the use of packing to reduce well cavity space as a fire or explosion precaution. However, these references do not address the use of specifically designed well packing as a means of protecting well components from damage in case of fire.
There is a need for a means of protecting the structural components of both injection wells and production wells used for hydrocarbon recovery from damage which can occur during a well fire or a fire in a substrate near a well, either of which cause thermal stress and possible burning of such structural components. The means available prior to the present invention were not always reliable because they required an active response to an indication of the fire. The present invention provides passive protection of the well structural components.